Drilling and producing deep water subsea wells

ABSTRACT

Subsea wells are drilled and completed with an offshore floating platform in a manner that allows simultaneous work on more than one well. A first well is drilled and cased. Then a tubing hanger is run through a drilling riser and landed in the wellhead housing. Then, with the same floating platform, the drilling riser is disconnected and moved to a second well. While performing operations on the second well, the operator lowers a production tree from the floating platform on a lift line, and connects it to the first wellhead housing. An ROV assisted subsea plug removal tool is used for plug removal and setting operations.  Seabed separation is configured upstream of a production choke valve.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority to provisional application 60/425,377,filed Nov. 12, 2002.

BACKGROUND OF THE INVENTION

A typical subsea wellhead assembly has a high pressure wellhead housingsupported in a lower pressure wellhead housing and secured to casingthat extends into the well. One or more casing hangers land in thewellhead housing, the casing hanger being located at the upper end of astring of casing that extends into the well to a deeper depth. A stringof tubing extends through the casing for conveying production fluids. AChristmas or production tree mounts to the upper end of the wellheadhousing for controlling the well fluid. The production tree is typicallya large, heavy assembly, having a number of valves and controls mountedthereon.

One type of tree, sometimes called “conventional” or “vertical”, has twobores through it, one of which is the production bore and the other isthe tubing annulus access bore. In this type of wellhead assembly, thetubing hanger lands in the wellhead housing. The tubing hanger has twopassages through it, one being the production passage and the otherbeing an annulus passage that communicates with the tubing annulussurrounding the tubing. Access to the tubing annulus is necessary, bothto monitor and bleed down pressure during production and to circulatefluids down the production tubing and up through the tubing annulus, orvice versa, to either kill the well or circulate out heavy fluid duringcompletion. After the tubing hanger is installed and before the drillingriser is removed for installation of the tree, plugs are temporarilyplaced in the passages of the tubing hanger. The tree has isolationtubes that stab into engagement with the passages in the tubing hangerwhen the tree lands on the wellhead housing. This type of tree isnormally run on a completion riser that has two strings of conduit. In adual string completion riser, one string extends from the productionpassage of the tree to the surface vessel, while the other extends fromthe tubing annulus passage in the tree to the surface vessel. The plugsare retrieved on wireline through the completion riser, then thecompletion riser is retrieved. While workable, it is time consuming,however to assemble and run a dual string completion riser. Also,drilling vessels may not have such a completion riser available,requiring one to be supplied on a rental basis.

In another type of tree, sometimes called “horizontal” tree, there isonly a single bore in the tree, this being the production passage. Thetree is landed before the tubing hanger is installed, then the tubinghanger is lowered and landed in the tree. The tubing hanger is loweredthrough the riser, which is typically a drilling riser. A wireline plugis run through the tubing hanger running string and installed in thetubing hanger. After removal of the tubing hanger running tool, aninternal tree cap is lowered through the drilling riser and installed inthe bore of the tree. Access to the tubing annulus is available throughchoke and kill lines of the drilling riser. The tubing hanger does nothave an annulus passage through it, but a bypass extends through thetree to a void space located above the tubing hanger. This void spacecommunicates with the choke and kill lines when the blowout preventer isclosed on the tubing hanger running string. In this system, the tree isrun on drill pipe, which prevents the drilling rig derrick of thefloating platform from being employed on another well while the tree isbeing run. This is also the case for the “conventional” tree, wheninstalled on completion riser or drill pipe.

In another and less common type of wellhead system, a concentric tubinghanger lands in the wellhead housing in the same manner as aconventional wellhead assembly. The tubing hanger has a productionpassage and an annulus passage. However, the production passage isconcentric with the axis of the tubing hanger, rather than slightlyoffset as in conventional tubing hangers. The tree does not have avertical tubing annulus passage through it, thus a dual bore completionriser is not required. Consequently the tree may be run on a monoboreriser. A tubing annulus valve is located in the tubing hanger since aplug cannot be temporarily installed and retrieved from the tubingannulus passage with this type of tree.

Normally, the tubing annulus valve is a check valve that prevents upwardflow that might occur through the tubing annulus but allows downwardflow. A disadvantage is that one cannot readily test a tubing annuluscheck valve to determine whether or not it is properly closing. A tubingannulus valve that is hydraulically actuated and which could be testedfrom above is desireable. However, these typically require hydraulicpassages in the tubing hanger, which take up space and add complexity tothe tubing hanger, rendering the designs potentially unreliable due tospace restrictions.

During subsea well drilling, the floating platform may complete only onewell at a time for production. However, in some instances, a platformmight drill and case a number of nearby wells, and defer running theproduction trees until later. The production trees may be ran by thesame platform or another. There have been instances where a tree was runby a lift line by a vessel onto a wellhead housing previously installedby another vessel. Generally, however, trees are run either on acompletion riser or on drill pipe because they are large and very heavy.Both of these procedures require a derrick and drawworks. Drilling awell or running tubing also requires a derrick and drawworks, andtypically, a floating platform has only one. Being unable to run aproduction tree from a platform at the same time that the platform isdrilling or completing another slows field development.

SUMMARY OF THE INVENTION

In one part of this method, more than one subsea well is undergoingcompletion and/or drilling simultaneously from the same floatingplatform. The operator drills and cases a first well with the use of adrilling riser. Then, the operator disconnects the drilling riser fromthe first well and begins operations on a second well. Preferably, afterdisconnecting the drilling riser from the first wellhead, the operatormoves the platform a short distance to position the derrick above thesecond well. While at least some of the operations are taking place onthe second well, the operator lowers from the same platform a productiontree onto the first wellhead housing, using a lift line.

Preferably, before disconnecting the riser from the first well andlowering the tree, the operator runs tubing, perforates the first well,and sets a plug in the tubing hanger. In the preferred embodiment, theplug is subsequently removed from the tubing hanger through the treewith the assistance of a remote operated vehicle (ROV) plug removaltool. Also, in the preferred embodiment, the tubing hanger has a tubingannulus valve that is normally closed and can be selectively openedafter the tree lands on the wellhead housing. As the tree lands on thewellhead housing, an orientation member associated with the tubinghanger orients the tree.

In another aspect of the invention, the tree is connected to a flowlineleading to a subsea fluid separator. The outlet of the subsea fluidseparator leads to a choke to control the flowrate. The choke leads to asubsea manifold. This arrangement is important in minimizing flowdisturbance prior to entering the separator, and supports optimumefficiency within the separation system.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1A and 1B comprise a vertical sectional view of a wellheadassembly constructed in accordance with this invention.

FIG. 2 is an enlarged sectional view of a portion of the wellheadassembly of FIGS. 1A and 1B, the sectional plane being different than inFIGS. 1A and 1B.

FIG. 3 is an enlarged sectional view of a portion of the wellheadassembly of FIGS. 1A and 1B.

FIG. 4 is an another sectional view of a portion of the wellheadassembly of FIGS. 1A and 1B, but shown in same sectional plane as inFIG. 2 to illustrate a tubing annulus valve in a closed position.

FIG. 5 is an enlarged sectional view of the tubing annulus valve of FIG.4, shown in an open position and engaged by an engaging member of theproduction tree.

FIG. 6 is an enlarged sectional view of the tubing annulus valve of FIG.4, shown in a closed position while a tubing hanger running tool isbeing connected to the tubing hanger.

FIG. 7 is a sectional view of the tubing annulus valve as shown in FIG.6, but shown in an open position.

FIG. 8 is a sectional view of the wellhead housing of the wellheadassembly of FIGS. 1A and 1B after running casing and in the process ofreceiving a BOP orientation spool.

FIG. 9 is a schematic horizontal sectional view of the wellhead housingof FIG. 8, the dotted lines showing a flowline connector arm beingrotated.

FIG. 10 is a perspective view of the wellhead assembly of FIGS. 1A and1B, after the BOP orientation spool of FIG. 8 has landed.

FIG. 11 is a schematic vertical sectional view of the wellhead assemblyof FIGS. 1A and 1B, showing an ROV deployed plug tool mounted on thetree.

FIG. 12 is a schematic side view of the plug tool of FIG. 11, with aplug setting attachment.

FIG. 13 is a schematic sectional view of a plug retrieving attachmentfor the plug tool of FIG. 11, shown in a disengaged position with a plugillustrated by the dotted lines.

FIG. 14 is a more detailed sectional view of the plug retrievingattachment of FIG. 13, shown in an engaged position.

FIG. 15 is a schematic view of a drilling platform in engagement withone subsea wellhead assembly, while a lift line on the platform is inengagement with another subsea wellhead assembly.

FIG. 16 is a vertical sectional view of an alternate embodiment of theportion of the tree of FIGS. 1A and 1B that connects to the innerwellhead housing.

FIG. 17 is a perspective view of the wellhead assembly of FIGS. 1A and1B, with a tree installed thereon.

FIG. 18 is an enlarged perspective view of one connector of a flowlinejumper for connecting to the tree of FIG. 1.

FIG. 19 is a perspective view of the flowline jumper of FIG. 18.

FIG. 20 is a schematic view of the flowline jumper of FIG. 18, shownbeing lowered into the sea.

FIG. 21 is a schematic view of the flowline jumper of FIG. 18, shownbeing stabbed into the tree flowline connector.

FIG. 22 is a schematic view of the flowline jumper of FIG. 18, showing aremote operated vehicle in the process of connecting to the flowlinejumper.

FIG. 23 is a schematic view of the flowline jumper of FIG. 18, showingthe ROV landed on a subsea manifold and connected by a pull line to theflowline jumper.

FIG. 24 is a schematic view of the flowline jumper of FIG. 18, showingthe pull line being retracted by the ROV, drawing the second connectorof the flowline jumper into alignment with the manifold.

FIG. 25 is a schematic view of the flowline jumper of FIG. 18, showingthe second connector of the flowline jumper being connected to thesubsea manifold.

FIG. 26 is a schematic view of the flowline jumper of FIG. 18, showingthe remote operated vehicle connecting the couplings of the flowlinejumper and the tree to each other.

FIG. 27 is a schematic view of the flowline jumper of FIG. 18, showingthe installation completed and the ROV being retrieved.

FIG. 28 is a perspective view of a second embodiment of a flowlinejumper.

FIG. 29 is a schematic of a production system for the wellhead assemblyof FIGS. 1A and 1B.

FIG. 30 is a schematic sectional view of one of the separators shown inFIG. 29.

FIG. 31 is an enlarged schematic sectional view of the separator of FIG.30, taken along the line 31—31 of FIG. 30, illustrating the coalescenceseparator portion.

FIG. 32 is an enlarged schematic view of a dielectrophoresis separatorportion of the separator of FIG. 30.

FIG. 33 is an enlarged schematic sectional view of the separator of FIG.30, taken along the line 33—33 of FIG. 30, illustrating thedielectrophoresis separator portion.

DETAILED DESCRIPTION OF THE INVENTION

Overall Structure of Subsea Wellhead Assembly

Referring to FIG. 1B, a lower portion of a wellhead assembly 11 includesan outer or low pressure wellhead housing 13 that locates on the seafloor and is secured to a string of large diameter conductor pipe 15that extends into the well. In this embodiment, a first string of casing17 is suspended on a lower end of outer wellhead housing 13 by a hanger19. However, casing 17 and hanger 19 are not always suspended from theouter wellhead housing 13 and can be eliminated in many cases.

An inner or high pressure wellhead housing 21 lands in and is supportedwithin the bore of outer wellhead housing 13. Inner wellhead housing 21is located at the upper end of a string of casing 23 that extendsthrough casing 17 to a greater depth. Inner wellhead housing 21 has abore 25 with at least one casing hanger 27 located therein. Casinghanger 27 is sealed within bore 25 and secured to the upper end of astring of casing 29 that extends through casing 23 to a greater depth.Casing hanger 27 has a load shoulder 28 located within its bore or bowl.

In this embodiment, a tubing hanger 31 is landed, locked, and sealedwithin the bore of casing hanger 27, or alternatively may lock into thebore of high pressure wellhead housing 21, or an adapter bowl located inthe high pressure wellhead housing. Referring to FIG. 2, tubing hanger31 has a lower end that lands on load shoulder 28. A seal 30 sealsbetween the exterior of tubing hanger 31 and the bore of casing hanger27 above load shoulder 28. A split lock ring 34 moves from a retractedposition radially outward to lock tubing hanger 31 to an internalprofile in casing hanger 27, or high pressure wellhead housing 21, or anadapter bowl. A sleeve 36, when moved axially downward, energizes seal30 as well as pushes lock ring 34 to the locked position. Tubing hanger31 is secured to the upper end of a string of production tubing 33.Tubing hanger 31 has a production passage 32 that is coaxial with tubing33.

Referring to FIG. 3, inner wellhead housing bore 25 has a lower portion25 a that has a smaller diameter than upper portion 25 b. The differencein diameters results in a conical generally upward facing transitionportion or shoulder 25 c located between portions 25 a and 25 b.Wellhead housing bore upper portion 25 b has a grooved profile 35 formedtherein above tubing hanger 31. Profile 35 is located a short distancebelow rim 37, which is the upper end of inner wellhead housing 21.

As shown in FIG. 1A, a Christmas or production tree 39 has a lowerportion that inserts into wellhead housing 21. Production tree 39 has aproduction passage 41 extending through it that has an outlet port 41 aextending laterally outward. Production tree 39 has an isolation tube 43that depends downward from its lower end and stabs sealingly intoproduction passage 32 of tubing hanger 31. The lower end of productiontree 39 extends into bore 25 of inner wellhead housing 21 towards boretransition section 25 c (FIG. 3).

Referring again to FIG. 3, an orientation sleeve 44 is a part of andextends upward from tubing hanger 31. Orientation sleeve 44 isnonrotatably mounted to the exterior of the body of tubing hanger 31.Orientation sleeve 44 has a helical or tapered contour formed on itsupper edge. A mating orientation sleeve 46 with a matching contour onits lower edge is secured to the lower end of production tree 39. Whentree 39 is lowered into wellhead housing 21, orientation sleeve 46engages the matching contour of orientation sleeve 46 to rotateproduction tree 39 and accurately orient it in the desired directionrelative to tubing hanger 31. The capture range of the helical/taperedinterface directly affects the height of the orientation sleeve. Inorder to minimize the effect of this onto the system, the tree can benominally pre-aligned via a supplementary mechanical register, via thestructural sub-frame 133. This is achieved in the same manner, typifiedby a pin to funnel arrangement, as that described later for registeringthe correct orientation of the BOP orientation spool.

Tree and Wellhead Housing Internal Connector

Tree 39 includes a connector assembly for securing it to wellheadhousing 21. The connector assembly includes a connector body 45 that hasa downward facing shoulder 47 that lands on rim 37. Connector body 45 isrigidly attached to tree 39. A seal 49 seals between rim 37 and shoulder47. Connector body 45 also extends downward into wellhead housing 21. Alocking element 51 is located at the lower end of connector body 45 forengaging profile 35. Locking element 51 could be of a variety of types.In this embodiment, locking element 51 comprises an outer split ringthat has a mating profile to groove 35. A plurality of dogs 53 locatedon the inner diameter of locking element 51 push locking element 51radially outward when moved by a cam sleeve 55. Cam sleeve 55 movesaxially and is hydraulically driven by hydraulic fluid supplied to apiston 57, or else by rods connected to externally mounted hydrauliccylinders.

The connector assembly has an extended or retainer portion 59 thatextends downward from connector body 45 in this embodiment. Extendedportion 59 is located above and secured to orientation sleeve 44. Acollar 60 is threaded to the outer diameter of extended portion 59 forretaining locking element 51 and dogs 53 with connector body 45.Alternately dogs 53 could be used to engage profile 35 and lockingelement 51 omitted. In that case, windows could be provided for the dogsin connector body 45, and extended portion 59 and collar 60 would beintegrally formed with connector body 45.

Referring to FIG. 1A, a control passage 61 extends through tree 39 to anexterior side portion, typically for supplying control fluid. Althoughnot shown, there are a number of these passages, and they lead toconnector tubes on the lower end of tree 39. The connector tubes stabinto mating passages on the upper end of tubing hanger 31. Thesepassages lead to hydraulic and/or electrical control lines that are notshown but extend below tubing hanger 31 on the outside of productiontubing 33. These control lines lead to downhole equipment in the stringof tubing 33, such as a downhole safety valve and downhole pressure andtemperature monitoring devices.

At least one valve is mounted to production tree 39 for controllingfluid flow. In the preferred embodiment, the valves include a mastervalve 63 and a swab valve 65 located in production passage 41. A safetyshutoff valve 67 is mounted to port 41 a. The hydraulic actuator 68 forsafety shutoff valve 67 is shown. Valves 63 and 65 may be eitherhydraulically actuated or mechanically actuated (typically by ROV).

Referring again to FIG. 1A, tree 39 has a mandrel 81 on its upper endthat protrudes upward. Mandrel 81 is typically sized for receiving aconnector for connection to a small diameter, lightweight riser, such asfor certain workover purposes. Mandrel 81 also enables other methods ofintervention.

Tubing Annulus Access

FIG. 4 illustrates a tubing annulus passage 83, which is not shown inFIG. 1B or 3 because tubing annulus passage 83 is located in a differentvertical sectional plane than that shown in FIGS. 1B and 3. Tubingannulus passage 83 extends vertically through tubing hanger 31 from anupper end portion to a lower end, where it communicates with a tubingannulus 85 surrounding tubing 33. The upper and lower ends of tubingannulus passage 83 may be slightly radially offset from each other, asshown in FIG. 4. An annular void space 87 surrounds isolation tube 43between the upper end of tubing hanger 31 and the lower end of tree 39.

A tubing annulus valve 89 is mounted in tubing annulus passage 83 toblock tubing annulus passage 83 from flow in either direction whenclosed. Referring to FIG. 5, tubing annulus valve 89 has a stem base 91that is secured by threads 93 to tubing annulus passage 83. A stem 95extends upward from stem base 91 along the axis of tubing annuluspassage 83. An enlarged valve head 97 forms the upper end of stem 95.Valve head 97 has a secondary resilient seal as well as a primary lipseal 99 made of metal in this embodiment.

A shuttle sleeve 101 is reciprocally carried in tubing annulus passage83. While in the upper closed position shown in FIGS. 4 and 6, the upperend of sleeve 101 is a short distance below an upper end portion oftubing hanger 31. While in the lower open position, shown in FIGS. 5 and7, sleeve 101 is in a lower position relative to valve head 97. Sleeve101 has a reduced diameter port or seat 103 formed in its interior. Seat103 is sealingly engaged by lip seal 99 as well as the resilient seal ofvalve head 97 while sleeve 101 is in the lower position.

An outward biased split ring 105 is mounted to the outer diameter ofsleeve 101 near its upper end. Split ring 105 has a downward taperedupper surface and a lower surface that is located in a planeperpendicular to the axis of tubing annulus passage 83. A mating groove107 is engaged by split ring 105 while sleeve 101 is in the upper,closed position. Split ring 105 snaps into groove 107, operating as adetent or retainer to prevent downward movement of sleeve 101.

FIG. 5 shows an engaging tool or member 109 extending into the upper endof tubing annulus passage 83 into engagement with the upper end ofsleeve 101. Engaging member 109 is a downward extending component oftree 39 (FIG. 1A) and is used for moving sleeve 101 from the upper tothe lower position. A second identical engaging member 109′, shown inFIGS. 6 and 7, is mounted to a running tool 111 used to run tubinghanger 31. Engaging member 109 has a lip 113 on its lower end that mateswith the upward facing taper on split ring 105. Lip 113 slides over andcauses split ring 105 to contract, enabling engaging member 109 to pushsleeve 101 downward to the open position. A spring 115, which may be aplurality of Belleville washers, is located between stem base 91 and thelower end of sleeve 101. Spring 115 urges sleeve 101 to the upper closedposition. Any pressure in passage 83 would assist spring 155 in movingsleeve 101 to the closed position.

Engaging member 109 is secured to the lower end of an actuator 117,which is mounted in tree 39. Actuator 117 is a hollow, tubular memberwith open ends reciprocally carried in a tubing annulus passage 118 intree 39 (FIG. 3). Actuator 117 has a piston portion on its exterior sidewall that is selectively supplied with hydraulic fluid for movingactuator 117 between upper and lower positions. Tubing annulus passage118 extends through tree 39 to an exterior side portion of tree 39 forconnection to a tubing annulus line that leads typically to a subseamanifold or an umbilical that serves the tree. Tubing annulus passage intree 118 does not extend axially to the upper end of tree 39.

When actuator 117 is moved to the lower position, engaging member 109engages and pushes sleeve 101 from the closed position to the openposition. FIGS. 6 and 7 show a similar actuator 117′ that forms a partof running tool 111 and works in the same manner as actuator 117. Likeactuator 117, actuator 117′ has a piston portion that is carried in ahydraulic fluid chamber for causing the upward and downward movement inresponse to hydraulic pressure. Passage 118′ leads to an exterior upperportion of running tool 111 for delivering and receiving tubing annulusfluid.

Running tool 111 has conventional features for running tubing hanger 31,including setting a seal between tubing hanger 31 and bore 25 ofwellhead housing 21 (FIG. 4). Running tool 111 has a lock member 119that is radially and outwardly expansible into a mating groove formed inan interior upward extending sleeve portion of tubing hanger 31. Lockmember 119 secures running tool 111 to tubing hanger 31 while tubing 33is being lowered into the well. Lock member 119 is energized andreleased by a lock member actuator 121, which is also hydraulicallydriven. Running tool 111 has a sleeve 123 that slides sealingly into thebore 32 of tubing hanger 31. Sleeve 123 isolates the upper end of tubingannulus passage 83 from production passage 32 (FIG. 4) in tubing hanger31.

Orientation

Referring to FIG. 8, a ring 125 is mounted to the exterior of outerwellhead housing 13, also referred to as a conductor housing. Ring 125has a depending funnel 127 and is selectively rotatable on outerwellhead housing 13 for orienting tubing hanger 31 and tree 39 (FIG. 3)in a desired position relative to other subsea wells and equipment. Alock pin or screw 129 will selectively lock ring 125 in the desiredposition. An arm bracket 131 is mounted to ring 125 for rotationtherewith. Arm bracket 131 cantilever supports a horizontally extendingarm 133. Arm 133 has an upward facing socket on its outer end 131. Also,a guide mechanical register 137 protrudes upward from arm 133, depictedand typified by a pin.

Ring 125 is normally installed on outer wellhead housing 13 at thesurface before outer wellhead housing 13 is lowered into the sea. Arm133 will be attached to arm bracket 131 below the rig floor but at thesurface. After outer wellhead housing 13 is installed at the sea floor,if necessary, an ROV may be employed later in the subsea constructionphase to rotate ring 125 and/or arm 133, to a different orientation,typically towards a manifold connection point.

A BOP (blowout preventer) adapter 139 is being shown lowered over inneror high pressure housing 21. BOP orientation spool 139 is used to orienttubing hanger 31 (FIG. 3) relative to arm 133. BOP orientation spool 139is preferably lowered on a lift line after the well has been drilled andcasing hanger 27 installed. The drilling riser, along with the BOP, willhave been removed from the upper end of inner wellhead housing 21 priorto lowering BOP orientation spool 139 in place. Alternatively, the BOPorientation spool may be deployed with the BOP and riser system, subjectto rig handling limitations. BOP orientation spool 139 has a guidesocket 143 that is mounted to its exterior at a point for aligning withpin 137. A funnel 141 on the lower end of BOP orientation spool 139assists in guiding BOP orientation spool 139 over inner wellhead housing21. Socket 143 will orient BOP orientation spool 139 to a positiondepending upon the orientation of arm 133 and pin 137. An ROV (notshown) will be used to assist guide socket 143 in aligning with guidepin 137.

BOP orientation spool 139 has a plurality of dogs 145 that arehydraulically energized to engage an external profile on inner wellheadhousing 21. BOP orientation spool 139 also has seals (not shown) thatseal its bore to bore 25 of wellhead housing 21. A helical orientingslot 147 is located within the bore of BOP orientation spool 139. Slot147 is positioned to be engaged by a mating pin or lug on running tool111 (FIG. 6) for tubing hanger 31. This engagement causes running tool111 to orient tubing hanger 31 in a desired orientation relative to theorientation of arm 133. Alternatively, a radially actuated pin (operatedvia mechanical or hydraulic means, using an ROV) is mounted within theBOP orientation spool, that engages with a helix on the tubing hangerrunning tool. One example of why this alternative method may be used,would be the use of a “slim” tubing hanger (typically 13⅝″ nom. OD)inside a traditional 18¾″ BOP and riser system, such that the “reach” ofthe pin/lug of the tubing hanger running tool would be unable to bridgethe gap.

FIG. 10 is a perspective view showing BOP orientation spool 139 inposition on inner wellhead housing 21, which is not shown in FIG. 10because it is located within the bore of BOP orientation spool 139. BOPorientation spool 139 has an upper end with a mandrel 146. The drillingriser and BOP will connect to the external profile on mandrel 146 afterBOP orientation spool 139 has been connected to inner wellhead housing21, unless the BOP orientation spool is deployed via the BOP and risersystem.

Once BOP orientation spool 139 has oriented tubing hanger 31 (FIG. 1B),the well will typically be perforated and tested. Tubing hanger 31 mustbe oriented relative to the arm 133 because orientation sleeve 44 (FIG.3) of tubing hanger 31 provides final orientation to tree 39, as shownin FIGS. 1A and 1B. Tree 39 has a tree funnel 148 that slides over innerwellhead housing 21 as it is landing.

The safety shutoff valve 67 of tree 39 is connected to a flow line loop149 that leads around tree 39 to a flow line connector 151 on theopposite side as shown in FIG. 1B. Flow line connector 151 will connectto a flow line 153 that typically leads to a manifold or subseaprocessing equipment. In this embodiment, flow line 153 is mounted to avertical guide pin or mandrel 155 that stabs into guide funnel 135 toorient to tree 39. Other types of connections to flow line connector 151could also be employed. Consequently, tree is oriented so that itsflowline connector 151 will register with flowline 153.

Plug Retrieval and Installation

After tree 39 is installed, a plug 159 (FIG. 12) must be removed from aplug profile 157 located within tubing hanger 31, as shown in FIG. 11.Plug 159 maintains pressure that is within tubing 33 after BOPorientation spool 139 (FIG. 10) is removed and prior to installing tree39 (FIG. 1A). Plug 159 is conventional and has one or more seals 161that seal within production passage 41 of tubing hanger 31. Plug 159 hasa plurality of locking elements 163 that will move radially outwardbetween a retracted and an extended position. Locking elements 163engage a mating groove in profile 157.

Preferably, rather than utilizing wireline inside a workover riser, asis typical, an ROV deployed plug tool 165 is utilized. Plug tool 165does not have a riser extending to the surface, rather it is lowered ona lift line. Plug tool 165 has a hydraulic or mechanical stab 167 forengagement by ROV 169. Plug tool 165 lands on top of tree mandrel 81. Aseal retained in plug tool 165 engages a pocket in mandrel 81 of tree39. When supplied with hydraulic pressure or mechanical movement fromROV 169, a connector 171 will engage mandrel 81 of tree 39. Similarly,connector 171 can be retracted by hydraulic pressure or mechanicalmovement supplied from ROV 169.

Plug tool 165 has an axially movable stem 173 that is operated byhydraulic pressure supplied to a hydraulic stab 174. A retrieving tool175 is located on the lower end of stem 173 for retrieving plug 159.Similarly, a setting tool 177 may be attached to stem 173 for settingplug 159 in the event of a workover that requires removal of tree 39.Setting tool 177 may be of a variety of types and for illustration ofthe principle, is shown connected by shear pin 179 to plug 159. Oncelocking elements 163 have engaged profile 157, an upward pull on stem173 causes shear pin 179 to shear, leaving plug 159 in place.

Retrieving tool 175, shown in FIGS. 13 and 14, may also be of a varietyof conventional types. In this embodiment, retrieving tool 175 has abody 181 that inserts partially into a receptacle 183 in plug 159. Alocator sleeve 185 on the exterior of body 181 will land on the rim ofreceptacle 183. A collet 187 is located within locator sleeve 185 andprotrudes below a selected distance. When locator sleeve 185 has landedon the rim of plug 159, collet 187 will be aligned with a groove 189within the plug 159.

Collet 187 and sleeve 185 are joined to a piston 191. Piston 191 issupplied with hydraulic fluid from ROV 169 (FIG. 10) via one of thestabs 174. A spring 193 is compressed while retrieving tool 175 is inthe released position, shown in FIG. 13. Spring 193 urges piston 191 toa lower position. When hydraulic pressure is relieved at passage 192,spring 193 will cause body 181 to move upward to the position shown inFIG. 14. In this position, a wall portion 194 of body 181 will locatedirectly radially inward of collet 187, preventing collet 187 fromdisengaging from profile 189. Once retrieving tool 175 is attached toplug 159, ROV 169 will actuate one of the hydraulic stabs or mechanicalinterfaces 174 to cause stem 173 (FIG. 11) to move upward. Collet 187causes dogs 163 to be radially retractable during this upward movementas plug 159 is disengaged. Once plug 159 is above tree valve 65, treevalve 65 may be closed, enabling the entire assembly of plug tool 165 tobe retrieved to the surface with a lift line.

Field Development

FIG. 16 schematically illustrates a preferred method for developing afield having a plurality of closely spaced wellhead assemblies 11. Thismethod is particularly useful in water that is sufficiently deep suchthat a floating platform 195 must be utilized. Platform 195 will bemaintained in position over the wells by various conventional means,such as thrusters or moorings. Platform 195 has a derrick 197 with adrawworks 199 for drilling and performing certain operations on thewells. Platform 195 also has a drilling riser 201 that is employed fordrilling and casing the wells. Drilling riser 201 is shown connected tohigh pressure housing 21 of one wellhead assembly 11. Drilling riser 201has a blowout preventer 203 within it. In the particular operationshown, a string of drill pipe 205 is shown extending through riser 201into the well.

Platform 195 also preferably has a crane or lift line winch 207 fordeploying a lift line 209. Lift line 207 is located near one side ofplatform 195 while derrick 197 is normally located in the center.Optionally, lift line winch 207 could be located on another vessel thattypically would not have a derrick 197. In FIG. 14, a tree 39 is shownbeing lowered on lift line 209.

Drilling and Completion Operation

In operation, referring to FIG. 8, outer housing 13 along with ring 125and arm 133 are lowered into the sea. Outer housing 13 is located at theupper end of conductor 15, which is jetted into the earth to form thefirst portion of the well. As conductor 15 nears the seabed, the entireassembly and arm 133 will be set in the desired position. This positionwill be selected based on which way the field is to be developed inregard to other wells, manifolds, subsea processing equipment and thelike. Once conductor 15 has been jetted into place and later in thesubsea construction program, the operator may release lock pins 129 androtate ring 125 to position arm 133 in a different orientation. Thissubsequent repositioning of arm 133 is performed as necessary or asfield development needs change to optimize connection points for thewell flowline jumpers.

The operator then drills the well to a deeper depth and installs casing117, if such casing is being utilized. Casing 117 will be cemented inthe well. The operator then drills to a deeper depth and lowers casing23 into the well. Casing 23 and high pressure wellhead housing 21 arerun on drill pipe and cemented in place. No orientation is needed forinner wellhead housing 21. The operator may then perform the same stepsfor two or three adjacent wells by repositioning the drilling platform195 (FIG. 15).

The operator connects riser 201 (FIG. 15) to inner wellhead housing 21and drills through riser 201 to the total depth. The operator theninstalls casing 29, which is supported by casing hanger 27. In somecases, an additional string of casing would be installed with the wellbeing drilled to an even greater depth.

The operator is then in position to install tubing hanger 31 (FIG. 1B).First, the operator disconnects drilling riser 201 (FIG. 15) and BOP 203and suspends it off to one side of wellhead assembly 11. The operatorlowers BOP orientation spool 139 on lift line 209 over inner wellheadhousing 21, as illustrated in FIG. 8. With the aid of an ROV, socket 143is positioned to align with pin 137. BOP orientation spool 139 is lockedand sealed to inner wellhead housing 21. BOP orientation spool 139 mayhave been previously installed on an adjacent well left temporarilyabandoned.

The operator then attaches drilling riser 201, including BOP 203, (FIG.15) to mandrel 146 (FIG. 10) of BOP orientation spool 139. The operatorlowers tubing 33 and tubing hanger 31 through drilling riser 201 onrunning tool 111 (FIG. 6), which is attached to a tubing hanger runningstring, which is a small diameter riser. Once running tool 111 isconnected to tubing hanger 31, actuator 117′ is preferably stroked tomove engaging member 109′ downward, thereby causing shuttle sleeve 101to move downward. This opens tubing annulus passage 83 for upward anddownward flow. Running tool 111 has a retractable pin (not shown) thatengages BOP orientation spool guide slot 147 (FIG. 8), causing it torotate tubing hanger 31 to the desired position as it lands withincasing hanger 27. Alternatively, the pin mounted on the BOP orientationspool is actuated by ROV to engage the tubing hanger running tool.

After tubing hanger 31 has been set, the operator may test the annulusvalve 89 by stroking actuator 117′ upward, disengaging engaging member109 from sleeve 101 as shown in FIG. 6. Spring 115 pushes sleeve 101 tothe upper closed position. In this position, valve head seal 99 will beengaging sleeve seat 103, blocking flow in either the upward or downwarddirection. While in the upper position, detent split ring 105 engagesgroove 107, preventing any downward movement.

The operator then applies fluid pressure to passage 118′ within runningtool 111. This may be done by closing the blowout preventer in drillingriser 201 on the small diameter riser above running tool 111. The upperend of passage 118′ communicates with an annular space surrounding thesmall diameter riser below the blowout preventer in drilling riser 201.This annular space is also in communication with one of the choke andkill lines of drilling riser 201. The operator pumps fluid down thechoke and kill line, which flows down passage 118′ and acts againstsleeve 101. Split ring 105 prevents shuttle sleeve 101 from movingdownward, allowing the operator to determine whether or not seals 99 onvalve head 97 are leaking.

The well may then be perforated and completed in a conventional manner.In one technique, this is done prior to installing tree 39 by lowering aperforating gun (not shown) through the small diameter riser in thedrilling riser 201 (FIG. 15) and through tubing 33. The smaller diameterriser may optionally include a subsea test tree that extends through thedrilling riser.

If desired, the operator may circulate out heavy fluid contained in thewell before perforating. This may be done by opening tubing annulusvalve 89 by stroking actuator 117′ and engaging member 109′ downward.Engaging member 109′ releases split ring 105 from groove 107 and pushessleeve 101 downward to the open position of FIG. 7. A port such as asliding sleeve (not shown) at the lower end of tubing 33 isconventionally opened and the blowout preventer in drilling riser 201 isclosed around the tubing hanger running string. The operator maycirculate down the running string and tubing 33, with the flow returningup tubing annulus 85 into drilling riser 201 and up a choke and killline. Reverse circulation could also be performed.

After perforating and testing, the operator will set plug 159 (FIG. 12)in profile 157 (FIG. 11) in tubing hanger production passage 32. Tubingannulus valve 89 is closed to the position of FIG. 6 by strokingactuator 117′ upward, causing spring 115 to move sleeve 101 upward. Theoperator then retrieves running tool 111 on the running string throughthe blowout preventer and drilling riser 201. The downhole safety valve(not shown) in tubing 33 is above the perforations and is preferablyclosed to provide a first pressure barrier; plug 159 in tubing hangerproduction passage 32 providing a second pressure barrier. Tubingannulus 85 normally would have no pressure, and tubing annulus valve 89provides a second (temporary) barrier in addition to the primarybarriers to wellbore pressure, these being the production tubing itselfand the production packer in the tubing completion system.

The operator then retrieves running tool 111 (FIG. 6) on the smalldiameter riser. The operator releases drilling riser 201 and BOP 203from BOP orientation spool 139 (FIG. 8) and retrieves BOP orientationspool 139 on lift line 209 (FIG. 15) or deploys BOP orientation spool139 on an adjacent well. The operator may then skid platform 195sequentially over the other wells for performing the same functions withBOP orientation spool 139 and drilling riser 201 for a different well.Once tubing 29 has been run and perforated on a particular well, thereis no more need for drilling riser 201 or derrick 197 (FIG. 15) at thatlocation. Even though platform 195 may have skidded out of alignmentwith the particular well (as an example, to continue operations on anadjacent well location), an ROV can guide lift line 209 down to engageand retrieve or move BOP orientation spool 139 in order to enablerecovery to surface or else movement to yet another adjacent well,within working proximity.

The operator is now in position for running tree 39 on lift line 209(FIG. 15). Tree 39 orients to the desired position by the finalengagement of the orienting members 44 and 46 (FIG. 3). This positionstree connector 151 in alignment with flowline connector 153, if such hadalready been installed, or at least in alignment with socket 127.Flowline connector 153 could be installed after installation of tree 39,or much earlier, even before the running of high pressure wellheadhousing 21. As tree 39 lands in wellhead housing 21, its lower end willmove into bore 25 of wellhead housing 21, and isolation tube 43 willstab into production passage 32 of tubing hanger 31. While beinglowered, orientation member 44 engages orientation sleeve 46 to properlyorient tree 39 relative to tubing hanger 31. Once landed, the operatorsupplies hydraulic fluid pressure to cam sleeve 55, causing dogs 53 topush locking element 51 (FIG. 2) to the outer engaged position withprofile 35. Flowline connector 151 (FIG. 1B) of tree 39 aligns withflowline connector 153, and the tubing annulus passage (not shown) intree 39 is connected to a manifold or a related facility.

Referring to FIGS. 11–13, in a preferred technique, with lift line 209(FIG. 15) and the assistance of ROV 169, the operator connects plug tool165 to tree mandrel 81 and removes plug 159 in tubing hanger 31 withretrieval tool 175. Tree valve 65 is closed once plug 159 is above it.Plug tool 165 may be retrieved and a tree cap installed, typically usingROV 169. Tree 39 should be ready for production.

Referring to FIG. 5, during production, tubing annulus valve 89 mayremain closed, but is typically held open for monitoring the pressure intubing annulus 85. If tubing annulus valve 89 is closed, it can beopened at any time by stroking actuator 117 (FIG. 5) of tree 39downward. Any pressure within tubing annulus 85 is communicated throughtubing annulus passage 118 in tree 39 and to a monitoring and bleedofffacility.

For a workover operation that does not involve pulling tubing 33, alight weight riser with blowout preventer may be secured to tree mandrel81. An umbilical line would typically connect the tubing annulus passageon tree 39 to the surface vessel. Wireline tools may be lowered throughthe riser, tree passage 41 and tubing 33. The well may be killed bystroking actuator 117 (FIG. 5) downward to open tubing annulus valve 89.Circulation can be made by pumping down the riser, through tubing 33,and from a lower port in tubing 33 to tubing annulus 85. The fluidreturns through tubing annulus passage 83 and passage 118 in tree 39 tothe umbilical line.

For workover operations that require pulling tubing 33, tree 39 must beremoved from wellhead housing 21. A lightweight riser would not berequired if tubing hanger plug 159 (FIG. 12) is reset into profile 157of tubing hanger 31 with plug tool 165 (FIG. 11). The operator installsplug tool 165 using lift line 209 (FIG. 15) and ROV 169. Plug 159 isattached to stem 173 and retrieval tool 177 and lowered into profile157. Once locking elements 163 latch into profile 157, the operatorreleases retrieval tool 177 from plug 159. The downhole safety valve intubing 33 typically would be closed during this operation. Tree 39 isretrieved on lift line 209 with the assistance of ROV 169. Then,drilling riser 201 (FIG. 15) is lowered into engagement with innerwellhead housing 21. The operator retrieves tubing 33 and performs theworkover in a conventional manner.

Alternate Embodiment

FIG. 16 shows an alternate embodiment for the internal connectorportions of a tree 210. Tree 210 is the same as tree 39, but for itsconnecting mechanism. Tree 210 has a plurality of dogs 211 that moveradially inward and outward between retracted and extended positions.Dogs 211 engage an internal profile 213 located within the bore ofwellhead housing 214. A cam 215, when moved axially upward, causes dogs211 to move radially outward.

Cam 215 is secured to a plurality of rods 217. Rods 217 lead to anannular piston 219, or else a plurality of hydraulic cylindersexternally mounted. Piston 219 has a lock chamber 22 that causes it tomove upward when supplied with hydraulic fluid pressure, moving cam 215to the upper position. Piston 219 also has an unlocking chamber 223.When supplied with hydraulic fluid pressure, the pressure in unlockingchamber 223 forces piston 219 downward to free dogs 211 to retract.Preferably the taper between cam 215 and dogs 211 is a locking taper sothat cam 215 will not move downward if hydraulic pressure fails.

Flowline Jumpers

FIG. 17 shows tree 39 installed, tree 39 typically having a controlassembly 225 mounted to it for controlling various valves (not shown)mounted to the tree. Alternately, the control of the various valves maybe handled in a control center separate from tree 39. The valves controlthe flow of fluids within and from tree 39. Flowline coupling 153 isaligned in position to mate with tree coupling 151. Couplings 153, 151may be of variety of types including collet, clamp, flange or othertypes. Flowline coupling 153 is mounted to one end of a flowline jumper226. Tree flowline connector 151 will have been previously oriented in adesired direction as discussed in connection with FIGS. 8 and 9.

Mandrel 155 extends from flowline coupling 153 for reception withinsocket 135. Mandrel 155 positions flowline coupling 153 in alignmentwith tree coupling 151 when jumper 226 is lowered into the sea from thesurface. As shown also in FIG. 18, a hinge mechanism 227 connectsflowline coupling. 153 and mandrel 155 to flowline jumper 226. Hingemechanism 227 allows flowline jumper 226 to move to a position parallelto mandrel 155, as illustrated by the dotted lines. In the connectedposition, coupling 153 is 90° relative to mandrel 155. Hinge mechanism227 may be of a variety of types, and in this embodiment, hingemechanism 226 comprises a clevis and a pair of pins 229 that rotatewithin holes in the clevis.

Referring to FIG. 19, flowline jumper 226 may be a single integralconduit or a number of sections secured together, such as by threads,flanged ends, or welding. Flowline jumper 226 may be of carbon steelalong with a number of other alloys such as titanium and chrome.Flowline jumper 226 may also be formed at least partially of compositematerials such as fiber in a resin. Flowline jumper 226 may be pre-bentinto an arcuate configuration or it may be sufficiently flexibly tocurve into the arcuate configuration when lowered. Furthermore, flowlinejumper 226 could be formed of flexible pipes that are made of multiplearticulated components that flex relative to each other. Flowline jumper226 may have a single passage through it or multiple passages.

Flowline jumper 226 also has at least a portion that is buoyant. In thisembodiment, a plurality of short buoyant segments 231 are secured overflowline jumper 226, forming a buoyant jacket. As shown in FIG. 19,segments 231 need not extend the full length of flowline jumper 226.However, they should extend sufficiently to cause the arcuate centralsection to float in a vertical plane. If not pre-bent into an arcuateshape, the length of flowline jumper 226 relative to its diameter willcause a portion to flex into an arcuate shape due to buoyancy even ifthe conduit of flowline jumper 226 is of steel. The flexibility offlowline jumper 226 is preferably sufficient to avoid any permanentdeformation due to the buoyancy of buoyant members 231. The buoyancyshould be adequate to provide buoyancy to the arcuate portion of jumper226 whether filled with water, hydrocarbon liquid or gas. Segments 231may serve as bend restrictors to prevent excessive bending of theconduit of flowline jumper 226.

A vertical connector 233 is located on the end opposite connector 153.Connectors 233 and 153 are preferably negatively buoyant for ease ininstallation. Connector 233, like connector 153, may be of a variety oftypes. When flowline jumper 226 is installed, a portion extending fromconnector 153 will be horizontal and a portion extending from verticalconnector 233 will be vertical. Buoyant members 231 cause the curvedportion adjacent vertical connector 233 to extend upward within avertical plane. The combination of the horizontal portion and arcuateportion over the length of jumper 226 may be termed a lazy wave.

FIGS. 20–27 illustrate one method for connecting wellhead assembly 11 toa second component, which in this case is a subsea manifold 235. Thesame method could be used for connecting manifold 235 to other subseacomponents, such as a subsea fluid processing unit. The second component235 could also be another flowline, or a daisy chain to another well.Manifold 235 receives flow from a number of subsea wells and routes thatflow to further processing equipment. The second component 235 couldinclude such equipment normally mounted to tree 39 (FIG. 1A), such as achoke, production/injection flow isolation valve, multi-phase flowmeters, erosion monitoring, corrosion monitoring and pressure andtemperature monitoring. The connection of flowline jumper 226 to subseawellhead assembly 11 could occur any time after running of low pressurewellhead housing 13.

The length of jumper 226 is greater than the horizontal distance betweenwellhead assembly 11 and manifold 235. The additional length issufficient for the lazy wave configuration shown in FIGS. 19 and 27,however the precise configuration and the additional length of jumper226 over the actual horizontal distance is not critical. The distancesbetween wellhead assembly 11 and manifold 235 may vary and could betypically as short as 30 meters and as long as several kilometers.

As shown in FIG. 20, lift line 209 is secured to one of the ends offlowline jumper 226. In this embodiment, it is shown secured to secondconnector 233. The negative buoyancy of first connector 153 has causedit to assume a lower elevation than any other portion of jumper 23 as itis being lowered. Also, the negative buoyancy has caused mandrel 155 tohinge over to an orientation parallel with flowline jumper 226. Flowlinejumper 226 is essentially straight and vertical in the positions ofFIGS. 20–23.

In FIG. 21, mandrel 155 (FIG. 17) is shown stabbing into socket 135while lift line 209 is still attached. Remote cameras may be used forguiding mandrel 155 into socket 135. Referring to FIG. 22, whileflowline jumper 226 is still vertical, an ROV 237 is shown optionallyattaching a pull line 239 to vertical connector 233. As shown in FIG.23, ROV 237 reels out pull line 239 and lands on manifold 237. Lift line209 still maintains flowline jumper 226 in the vertical orientation inFIG. 23. Then, as shown in FIG. 24, ROV 237 reels in pull line 239,causing second connector 233 to approach manifold 235, with lateralguidance where necessary. Hinge mechanism 227 (FIG. 18) allows firstconnector 153 and a portion of flowline jumper 226 to move to ahorizontal position. FIG. 25 shows ROV 237 connecting second connector233 to a suitable mandrel on manifold 235. Subsequently, as shown inFIG. 26, ROV 237 moves over into engagement with first connector 153.ROV 237 performs the actuation to cause first connector 153 to sealinglyengage and secure to tree coupling 151 (FIG. 1A).

FIG. 27 illustrates flowline jumper 226 in the desired position, withlift line 209 removed and being retrieved as well as ROV 237. Buoyantmembers 231 (FIG. 19) cause the arcuate portion of flowline jumper 226to float in a vertical plane after installation.

In the embodiment of FIG. 28, flowline jumper 241 may be constructed inthe same manner as flowline jumper 226 (FIG. 19). It may contain abuoyant jacket (not shown) over all of its length or a portion. Bothconnectors 243, 245 are vertical types such as connector 233 (FIG. 19).Consequently, the buoyancy of flowline jumper 241 causes the singlearcuate configuration to float in a vertical plane after installation.

Subsea Processing System

FIG. 29 illustrates schematically a subsea processing system for thevarious wellhead assemblies 11 within a field. The subsea processingsystem separates water and sand from the oil being produced. The systemincludes a plurality of separators 251. A single separator 251 may beutilized with each subsea well assembly 11, or more than one well 11 mayfeed into a separator 251, typically via a gathering system (manifold).

As shown in FIG. 30, each separator comprises a horizontal cylindricalvessel 253 that locates on the sea floor. Oil and water inlet 255 islocated on the upstream end of separator vessel 253. Oil outlet 257 islocated on the downstream end of separator vessel 253. Generally,greater water depths will require a higher wellhead delivery pressurewith corresponding lower actual free gas volumes. Lower free gas volumesare beneficial for oil/water separation, because fewer gas bubbles willmigrate vertically and disturb the horizontal flow pattern generated bythe oil and water flowing through the separator vessel 253. A low freegas percentage in the fluid also allows more of the separator vessel tobe utilized for oil/water separation.

In addition to the issue described above, higher pressure in itselfwithin separator vessel 253 will impact the separation. Preliminaryresults show that separation occurs easier at higher pressures. This canbe caused by the fact that high pressure causes the liquid hydrocarbonfraction to be lighter, hence increase the density difference betweenwater and oil. The hydrocarbon fraction becomes lighter because lighterhydrocarbon fractions are liquefied at the higher pressure, reducing theoverall density of the liquid hydrocarbon phase.

Separator vessel 253 is designed to withstand the high externalpressures due to the very deep water. Also, one may not reduce themaximum theoretical external pressure by anticipated internal pressurein the design calculations. Generally, smaller diameters will allow athinner wall thickness for the same external pressure. For example, a2.8 meter diameter cylinder requires 140 millimeters wall thickness towithstand a selected pressure. A 0.5 meter diameter cylinder willwithstand the same pressure with a wall thickness of 25 millimeters.Consequently, separator 253 has a fairly small diameter, preferably nomore than 1/10^(th) its length.

Separator 251 may be of various types for separating water and oil. Inthis embodiment, separator 259 employs a coalescence unit 259.Coalescence unit 259 has a plurality of tubes 261 within it, each of thetubes being at an electrical potential, as illustrated in FIG. 31. Ahigh voltage electrostatic field is applied to the oil and water mixtureat the tubes 261. By exposing the mixture of water and oil to anelectrostatic field, the dipolar water droplets contained in the oilphase are oriented in a way that makes them collide or coalesce witheach other. This causes the water droplets to grow to bigger droplets.Generally, bigger droplets move and separate faster than smallerdroplets. Consequently, a first separation from water and oil takesplace immediately after coalescence unit 259. This reduces the requiredretention time to remove water from the oil produced over a pure gravityseparation, allowing the separator vessel 253 diameter and volume to bereduced.

As shown in FIG. 31, preferably low voltage supplied from the surfacevia an umbilical line is routed through low voltage wires 263 into theinterior of separator vessel 253. A plurality of transformers 265transform the low voltage to the high voltage that is required for theelectrostatic field. The same low voltage power supply is utilized forother functions, such as operating the solenoids and sensors involvedwith control 225 (FIG. 17) of each subsea well 11.

If coalescence unit 259 is not adequate to reach the desired waterseparation performance, a second separator unit could be employed. Thesecond stage could be another coalescence unit or it could be a unit ofa different type, such as dielectrophoresis unit 267. Unit 267 also usesa high voltage electrostatic field, however the field is configured toforce the water droplets into designated sections of unit 267 andthereby form streams of water. Electrodes 269 in the form of undulatingsheets 269, as shown in FIGS. 32 and 33, are used. Electrode sheets 269are closely spaced and arranged side-by-side to define constrictivepassage portions and widened passage portions. The constrictive passageportions result from two adjacent valleys, while the widened passageportions result from two adjacent peaks of each electrode sheet 269.Sheets 269 force the water droplets to move towards the stronger sectionof the electrostatic field, which is at the narrower portions. Theforces imposed by the electrostatic field is in the order of magnitudetwo to five times greater than the gravity force. This phenomenon isused to guide the water droplets into these predetermined passageportions, where they form high water content sections of liquid thatwill easily separate immediately downstream of unit 267.Dielectrophoresis unit 267 reduces the time normally needed for aconventional gravity separator.

Referring again to FIG. 30, a bulkhead 271 extends upward from separatorvessel 253 near its downstream end. Bulkhead 271 has a height about halfthe diameter of separator vessel 253, thus defines a lower section forcollecting higher water concentrations. A water outlet 273 is located onthe bottom of separator vessel 253 upstream of bulkhead 271.

Referring back to FIG. 29, a choke 275 is preferably located downstreamof oil outlet 257. Choke 275 is a conventional device that provides avariable orifice for controlling pressure and flow rate. In the priorart, a choke is typically located on the tree, thus upstream of anyseparation process. In this embodiment, choke 275 is located downstreamof each separator 251 to prevent shearing and mixing of oil and water.

A flowline jumper 277 connects choke 275 to manifold 279. Flowlinejumper 277 may be constructed the same as jumper 226 (FIG. 19) or jumper241 (FIG. 28) or may be of more conventional form. Choke 275 could beincorporated as part of flowline jumper 277 such that it is lowered andinstalled with jumper 277. Alternately, choke 275 could be mounted tomanifold 279 or other subsea equipment.

Manifold 279 is depicted as a conventional unit that has a pair of lines281 and 283 that lead to the surface for delivery of the separated oiland any entrained gas therein. Jumpers 277 of each of the variousseparators 251 lead to manifold 279. In this embodiment, the separatedwater outlet 273 of each separator connects to a flowline 284 that leadsto a valve module 285. The various flowlines 284 join each other invalve module 285, with the combined flow leading from a line 286 to theintake of a subsea pump 287. Water pump 287 disposes of the water in aninjection well. A variety of equipment may be connected between waterpump 287 and the injection well. In this example, pump output line 288leads to a hydrocyclone or centrifugal separator 289 that separates sandfrom the liquid stream that has been produced from the wells.Hydrocyclone separator 289 has a sand output 291 that leads to a storagevessel 292 for periodic later disposal. For example, the sand could bepumped back into the casing annulus of one or more of the subseawellhead assemblies 11. Vessel 292 is shown connected to manifold 283via line 298. Periodically, the high pressure output of pump 287 isdirected into vessel 292, as indicated, to cause the accumulated sand tomove through line 298.

The liquid output 293 of hydrocyclone separator 289 leads to anotheroil/water separator 295 that is of a centrifugal or hydrocyclone typefor removing any final oil droplets located in the water stream. Theseparated oil leads through line 296 to the manifold line 283. The wateroutput of separator 295 must be substantially free of oil and leads toan injection flowline 297 for delivery to an injection well.

A valve 301 is connected to a line 303 that leads from the output ofpump 287. Line 303 branches into separate lines, each connected to oneof the lines 284 leading from one of the separators 251. Each line 303has a valve 305. Opening valves 301 and 305 enables the liquid beingpumped by pump 287 to flow backwards through one of the water outletlines 284 into the water outlet 273 for backflushing. Sand and otherdeposits accumulate in the subsea separation vessels 253. These sandsand/or deposits are removed from each separator 251 by the backflushinginjection through lines 284. The injection of water creates turbulencewithin each separator vessel 253 to cause the trapped sand and otherdeposits in separator 251 to flow with the produced oil out manifoldlines 281 and 283. Normally, backflushing fluid is delivered to only oneseparator 251 at a time.

The invention has significant advantages. The use of a light weight treeallows a lift line to be used to lower the tree onto the wellheadhousing. The use of the lift line frees up the derrick and drawworks foruse in drilling or completing another well simultaneously. The ROVactuated plug removal tool allows plugs to be pulled and set without theuse of a riser. The tubing annulus valve allows circulation withoutremoving plugs or requiring a dual string completion riser. Theorientation equipment and method allows changes in the orientationflowline jumper to be made after installation on the outer wellheadhousing. Locating the choke downstream of a subsea separator provideshigher pressure in the separator, which enhances separation. Selectiveback flushing of the separators permits discharge of solids and depositsfrom the system in a controlled a non-disruptive manner.

While the invention has been shown in only a few of its forms, it shouldbe apparent to those skilled in the art that it is not so limited but issusceptible to various changes without departing from the scope of theinvention.

1. A method of drilling and completing a plurality of subsea wells,comprising: (a) with a well drilling derrick assembly on a floatingplatform, connecting a drilling riser to a first wellhead housing,drilling and casing a first well, then running a string of tubing andlanding a tubing hanger in the first wellhead housing; (b) with the welldrilling derrick assembly on the floating platform, disconnecting thedrilling riser from the first wellhead housing, connecting the drillingriser to a second wellhead housing, and performing operations on asecond well; and (c) while performing at least part of the operations onthe second well in step (b), connecting to a production tree lift linefrom a lift line winch that is on the same floating platform and spacedaway from the well drilling derrick assembly, and lowering theproduction tree on the lift line to the first wellhead housing andconnecting the tree to the first wellhead housing.
 2. The methodaccording to claim 1, wherein: during step (a) the well drilling derrickassembly of the platform is located over the first wellhead housing; and(b) the platform is moved from the position in step (a) after thedrilling riser is
 3. The method according to claim 1, wherein step (a)further comprises perforating the first well and setting a plug withinthe tubing hanger.
 4. A method of drilling and completing a plurality ofsubsea wells, comprising: (a) with a floating platform, connecting adrilling riser to a first wellhead housing, drilling and casing a firstwell, then running a string of tubing and landing a tubing hanger in thefirst wellhead housing; (b) with the floating platform, disconnectingthe drilling riser from the first wellhead housing, connecting thedrilling riser to a second wellhead housing, and performing operationson a second well; (c) while performing at least part of step (b),lowering a production tree on a lift line from the same floatingplatform and connecting the tree to the first wellhead housing; whereinstep (a) further comprises perforating the first well and setting a plugwithin the tubing hanger; wherein the method further comprises afterstep (c): lowering a plug removal tool on the lift line and landing theplug removal tool on the tree; removing the plug with the plug removaltool; then disconnecting the plug removal tool from the tree andretrieving the plug removal tool on the lift line.
 5. A method ofdrilling and completing a plurality of subsea wells, comprising: step(a) with a floating platform, connecting a drilling riser to a firstwellhead housing, drilling and casing a first well, then running astring of tubing and landing a tubing hanger in the first wellheadhousing; (b) with the floating platform, disconnecting the drillingriser from the first wellhead housing, connecting the drilling riser toa second wellhead housing, and performing operations on a second well;(c) while performing at least part of step (b), lowering a productiontree on a lift line from the same floating platform and connecting thetree to the first wellhead housing; wherein: step (a) further comprisesproviding the tubing hanger with a tubing annulus valve and closing thetubing annulus valve prior to disconnecting the drilling riser from thefirst wellhead housing; and step (c) further comprises selectivelyopening the tubing annulus valve after the tree lands on the firstwellhead housing.
 6. A method of drilling and completing a plurality ofsubsea wells, comprising: (a) with a floating platform, connecting adrilling riser to a first wellhead housing, drilling and casing a firstwell, then running a string of tubing and land a tubing hanger in thefirst wellhead housing; (b) with the floating platform, disconnectingthe drilling riser from the first wellhead housing, connecting thedrilling riser to a second wellhead housing, and performing operationson a second well; step (c) while performing a least part of step (b),lowering a production tree on a lift line from the same floatingplatform and connecting the tree to the first wellhead housing; wherein:step (a) further comprises providing the tubing hanger with a tubingannulus valve that closes due to a spring bias prior to disconnectingthe drilling riser from the first wellhead housing; and step (c) furthercomprises providing the tree with a hydraulically powered actuator, andopening the tubing annulus valve with the actuator after the tree landson the first wellhead housing.
 7. A method of drilling and completing aplurality of subsea wells, comprising: (a) with a floating platform,connecting a drilling riser to a first wellhead housing, drilling andcasing a first well, then running a string of tubing and landing atubing hanger in the first wellhead housing; (b) with the floatingplatform, disconnecting the drilling riser from the first wellheadhousing, connecting the drilling riser to a second wellhead housing, andperforming operations on a second well; (c) while performing at leastpart of step (b), lower a production tree on a lift line from the samefloating platform and connecting the tree to the first wellhead housing;wherein step (a) further comprises: providing the tubing hanger with anorientation member and rotating the tubing hanger to a desiredorientation; and step (c) further comprises: providing the tree with anorientation member and engaging the orientation member of the tree withthe orientation member of the tubing hanger to rotate the tree in adesired final orientation.
 8. A method of drilling and completing aplurality of subsea wells, comprising: (a) with a floating platform,connecting a drilling riser to a first wellhead housing, drilling andcasing a first well, then running a string of tubing and landing atubing hanger in the first wellhead housing; (b) with the floatingplatform, disconnecting the drilling riser from the first wellheadhousing, connecting the drilling riser to a second wellhead housing, andperforming operations on a second well; (c) while performing at leastpart of step (b), lowering a production tree on a lift line from thesame floating platform and connecting the tree to the first wellheadhousing; (d) providing the tree with a flowline connector and rotatingthe tree to a desired orientation, while it is landing on the firstwellhead housing; and (e) connecting a flowline jumper to the flowlineconnector and to additiona subsea equipment.
 9. A method of drilling andcompleting a plurality of subsea wells, comprising: (a) with a floatingplatform, connecting a drilling riser to a first wellhead housing,drilling and casing a first well, then running a string of tubing andland a tubing hanger in the first wellhead housing; (b) with thefloating platform, disconnecting the drilling riser from the firstwellhead housing, connecting the drilling riser to a second wellheadhousing, and performing operations on a second well; (c) whileperforming at least part of step (b), lowering a production tree on alift line from the same floating platform and connecting the tree to thefirst wellhead housing; (d) providing the tree with a flowlineconnector; and (e) connecting a flowline jumper to the flowlineconnector and to additional subsea equipment, the flowline jumper havingan arcuate portion that is sufficiently buoyant to float in a verticalplane after installation.
 10. A method of drilling and completing aplurality of subsea wells, comprising: (a) with a floating platform,connecting a drilling riser to a first wellhead housing, drilling andcasing a first well, then running a string of tubing and land a tubinghanger in the first wellhead housing; (b) with the floating platform,disconnecting the drilling riser from the first wellhead housing,connecting the drilling riser to a second wellhead housing, andperforming operations on a second well; (c) while performing at leastpart of step (b), lowering a production tree on a lift line from thesame floating platform and connecting the tree to the first wellheadhousing; (d) connecting a subsea fluid separator to a subsea manifoldhaving flowlines leading to a surface processing facility; (e)connecting a flowline jumper from the tree to the subsea fluidseparator; (f) connecting a choke between the separator and the subseamanifold; and (g) flowing well fluid from the tree to the separator,separating heavier and lighter components of the well fluid in theseparator, and reducing pressure of the flowing well fluid product asthe well fluid flows through the choke to the manifold for transport tothe surface facility.